Casing Inspection Using Pulsed Neutron Measurements

ABSTRACT

A method for evaluating wellbore conduit condition includes using measurements of at least one of (i) inelastic gamma rays made during emission a burst of neutrons into the conduit from within the conduit at at least one spaced apart location from a position of the emission and (ii) epithermal neutrons or capture gamma rays therefrom detected at at least two spaced apart locations from the position of the emission within a selected time after the emission. The at least one of the measurements of inelastic gamma rays and epithermal neutron or capture gamma ray counts are characterized to estimate an amount of loss of iron in the conduit.

CROSS-REFERENCE TO RELATED APPLICATIONS

The current application is a continuation of, and claims the benefit ofU.S. patent application Ser. No. 14/325,255, filed on Jul. 7, 2014,published on Jan. 7, 2016 as U.S. Publication No. 2016/0003025, theentire content of which is incorporate by reference into the currentapplication.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

This disclosure is related to the field of pulsed neutron well loggingapparatus and methods. More specifically, the disclosure is related tousing pulsed neutron measurements to evaluate the condition of metalconduit (casing or liner) installed in wellbores drilled throughsubsurface formations.

Wellbores drilled through subsurface formations for the purpose ofproducing fluids, e.g., gas and/or oil may have a steel conduit such asa casing (a conduit that extends from the bottom of the wellbore to thesurface) or a liner (a conduit that extends from the bottom of the welland is sealingly engaged with a shallower depth conduit installed in thewellbore). The casing or liner is used to protect the mechanicalintegrity of the wellbore and to provide hydraulic isolation of thevarious formations penetrated by the wellbore, among other purposes.Because casing or liner is typically made from various steel alloys, itis subject to corrosion.

It is important, for example, in older wells or in wells where corrosivefluids are being produced to determine not only the properties of theformation or the borehole fluid, but also of the casing or liner itself.Various devices are known in the art for the inspection of the thicknessand surface quality (e.g. pitting, roughness or holes due to corrosion).Examples of such devices include: (i) ultrasonic logging tools(generally scan a transmitter/receiver pair and look for ultrasonicreflection); (ii) electromagnetic logging tools (measure total amount ofmetal present via eddy currents; (iii) multiple contact arm (“finger”)caliper tools (inspect the internal surface of the casing by tracing itwith a multitude of measurement fingers; and (iv) casing collar locatortools (very qualitative, but spikes in areas without casing collars canindicate casing issues).

The instruments described above may require that a wellbore tubing (aconduit having smaller diameter than the liner or casing used toincrease fluid velocity from the wellbore) has to be removed from thewellbore a priori, which may be expensive and inconvenient for routinecasing or liner inspection. The foregoing instruments provide no otherinformation than that about the condition of the casing or liner(although ultrasonic inspection may provide indications of quality ofthe cement used to retain the casing or liner, and the caliper tool mayprovide indication of scale buildup inside the casing).

Unless there is a specific wellbore maintenance and monitoring plan, oneusually only finds out about a problem after it occurs, because theabove described casing/liner evaluation devices are typically used tocharacterize a problem that has already manifested itself as a problemwith the wellbore (generally because of the above describedinconvenience and expense of removing wellbore tubing for inspectionpurposes using the above described instruments).

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an example wireline conveyed pulsed neutron well logginginstrument.

FIG. 2 shows another example pulsed neutron well logging instrument.

FIG. 3 shows an example of a net inelastic GR spectrum from a laboratorysandstone formation with casing showing energy peaks of differentcharacteristic elements including Fe from steel casing.

FIG. 4 shows an example well log placed next to a schematic drawing of acased wellbore having a tubing and packer. The log example is of IRAT(Inelastic ratio) and YFE (Inelastic Iron yield from spectroscopy) asindicators of casing condition.

FIG. 5 shows an example computer system that may be used in someembodiments.

DETAILED DESCRIPTION

FIG. 1 shows an example apparatus for evaluating subsurface formations131 traversed by a wellbore 132. The present example wellbore mayinclude a liner or casing 106 that may be evaluated using measurementsmade by a well logging instrument explained further below. A pulsedneutron well logging instrument 130 may be suspended in and moved alongthe interior of the wellbore 32 on an armored electrical cable 133, thelength of which substantially determines the relative depth of theinstrument 130. As is known in the art, this type of instrument can alsooperate in a well having tubing inserted inside the casing 106 or liner.The tubing is omitted from FIG. 1 for clarity of the illustration. Thelength of cable 133 may be controlled by suitable means at the surfacesuch as a drum and winch mechanism 134. The depth of the instrument 130within the wellbore 132 may be measured by encoders in an associatedsheave wheel 133, wherein the double-headed arrow representscommunication of the depth level information to the surface equipment.Surface equipment, represented at 107, may be of any type known in theart, and may include a processor subsystem and recorder (not shownseparately), and communicates with the well logging instrument 130. Itwill be understood that certain signal processing may be performed inthe well logging instrument 130 and/or at the surface, and that some ofthe processing may be performed at a remote location. Although theinstrument 130 is shown as a single body, the instrument 130 mayalternatively comprise separate components such as a cartridge, sonde orskid, and the well logging instrument 130 may be combinable with otherwell logging instrument. The pulsed neutron well logging instrument 130may, in a form hereof, be of a general type described for example, inU.S. Pat. No. 5,699,246, but the foregoing example of an instrument isnot a limitation on the scope of the present disclosure. The instrument130 may include a housing 111 in the shape of a cylindrical sleeve,which is capable, for example, of running in open wellbore, casedwellbore or through a production tubing (not shown as explained above).Although not illustrated in FIG. 1, the well logging instrument 130 mayalso have an eccentering device, for example a bow spring, for urgingthe instrument 130 against the wall of the wellbore casing 106. At leastone pulsed neutron generator (PNG) 115 may be mounted in the housing 111with a near-spaced radiation detector 116 and a far-spaced radiationdetector 117 mounted longitudinally above the PNG 115, each at aseparate axial distance therefrom. One or more further detectors (notshown) may also be provided, it being understood that when the near andfar detectors are referenced, use of further detectors can, wheneversuitable, be included as well. Acquisition, control, and telemetryelectronics 118 serves, among other functions, to control the timing ofburst cycles of the PNG 115, the timing of detection time gates for thenear 116 and far 117 radiation detectors and to telemeter count rate andother data using the cable 133 and surface telemetry circuitry, whichcan be part of the surface instrumentation 107. The surface processor ofsurface instrumentation 107 can, for example, receive detected neutroncounts, detected gamma rays and/or gamma ray spectral data from near andfar radiation detectors 116 and 117. The signals, whether raw detectormeasurements and/or processed data may be recorded as a “log”representing measured parameters with respect to depth or time on, forexample, a recorder in the surface instrumentation 107. The radiationdetectors may include one or more of the following types of radiationdetectors, epithermal neutron detectors (e.g., ³He proportional counterscovered by a shield to exclude thermal neutrons), and scintillationcounters (which may or may not be used in connection with a spectralanalyzer).

Pulsed neutron tools are commonly used for cased hole formationevaluation, because neutron radiation is one of the few means ofanalyzing materials behind a thick layer or iron (in this placerepresented by the casing).

FIG. 2 shows another example generic multi-detector pulsed neutronlogging instrument 30. Three scintillation type gamma ray detectors,116, 117, 119 are shown in the present example but for some applicationsa single detector may suffice. The detectors 116, 117, 119 may bedisposed at successively longer axial spacings from a neutron source115. Shielding 109 may be disposed between the neutron source 115 andthe nearest of the detectors 116 to reduce effects of neutrons beingdetected directly from the source 115. The telemetry electronics (118 inFIG. 1) or other electronics in the instrument 30 may include amulti-channel pulse height analyzer for each gamma ray detector. Suchanalyzers may characterize the energy level of each gamma ray detectedby each of the detectors 116, 117, 119 to enable certain types ofanalysis to be further explained below.

The neutron source 115 in the present example instrument may be a pulsedneutron generator, as explained with reference to FIG. 1. The neutrongenerator 115 can be based on either the deuterium-tritium reaction(with source energy of 14.1 MeV) or the deuterium-deuterium reaction(with the source energy of 2.45 MeV). Other suitable reactions couldalso be used for a pulsed neutron source. In some examples, the gammaray detectors 116, 117, 119 each may be supplemented by an epithermalneutron detector 116A, 117A, 119A. The epithermal neutron detectors maybe ³He proportional counters enclosed by a thermal neutron shieldingmaterial, such as a layer of cadmium metal, such that thermal neutronsare substantially excluded from the ³He proportional counters. Thus the³He proportional counters may detect substantially only epithermalneutrons.

The general concept of a pulsed neutron measurement is that the neutrongenerator 115 is turned on for a preselected time interval (e.g. for 20microseconds) and then is turned off for a selected period before asuccessive “on” period as above. The “off” period may have a wide rangeof time durations, for example, from 30 microseconds to 20 millisecondsor more. The specific sequence of “on” and “off” times for the neutrongenerator is called the “burst pattern.” The burst pattern may beoptimized for different measurement types. Measurements of the returninggamma rays by the gamma ray detectors 116, 117, 119 during the generator“on” time” (during the “burst”) and after the burst (during the “offtime”) may be used to determine certain properties of the mediasurrounding the instrument 30.

Examples of the types of measurements that may be made using pulsedneutron well logging instruments may be broadly be classified asfollows:

Detector ratios (gamma ray or neutron); Ratios of count rates betweendifferent detectors during any time of the burst pattern.

Detector count rates (gamma ray or neutron); Number of gamma rays orneutrons detected by each of the detectors in a given time period duringany time of the burst pattern and normalized by a neutron monitor (i.e.,a neutron detector placed proximate to the source to correct for outputvariations).

Decay times (gamma ray or thermal/epithermal neutrons); Decay of thenumber of gamma rays or neutrons detected by the detectors in a giventime period during any time of the burst pattern.

Energy window count rates; Number of gamma rays detected by thedetectors in a given energy range during any time of the burst pattern.These rates can be potentially normalized by the total count rate in aspectrum or by the neutron monitor or another gamma ray detector.

Energy spectrum relative yields; A fraction or percentage of the gammarays in the thermal neutron capture detection time interval (during aburst-off period) or inelastic gamma rays emitted during a burst-onperiod may be spectrally analyzed with respect to energy level todetermine amounts or fractional quantities of certain chemical elementsin the surrounding media by decomposing the measured gamma ray spectruminto components that are known to be characteristic of those elements(those components are referred to as standard spectra).

Herein are proposed several methods for determining the amount of casing(or liner) iron that is present in a wellbore having a casing or linerdisposed therein. Depending on methods of normalization, these methodscan be used quantitatively or qualitatively. The described methods canbe used individually or in combination.

A. Inelastic Iron Yields From Gamma Ray Spectral Analysis (InelasticYields May Be Particularly Useful in Wells Having a Large Amount ofThermal Neutron Absorbers)

FIG. 3 shows an example cased wellbore gamma ray energy spectrumrecorded by a gamma ray detector during a period when the neutrongenerator is on. The spectrum has been corrected for alteration causedby thermal neutron capture counts that also occur during the burst. Theexample spectrum clearly shows the features from the iron component Fe(i.e., the peak around 0.85 MeV), the oxygen component O, O′, O″ (i.e.,the peaks around 5-6 MeV) and the silicon component Si (i.e., the peakaround 1.8 MeV). A decomposition of the spectrum, using a techniqueknown in the art using so-called “standard spectra” for each element,can generate “yields” which give an indication of the relative amount ofan element that is present in the media surrounding the well logginginstrument. The example spectrum shown in FIG. 3 may be made using thegamma rays detected by only one of the detectors in the exampleinstrument shown in FIG. 2.

It is proposed to use the inelastic iron yield as an indicator of thepresence or absence of casing and/or tubing iron. Small corrections forformation iron may be needed in some cases, but the iron yield signalfrom the casing (or liner) generally dominates the inelastic yieldspectrum. A possible benefit of using inelastic gamma ray spectroscopyis that it is generally a more shallow (i.e., shorter lateral distancefrom the instrument) measurement, making it more sensitive to the medianear the tool. An example of the aforementioned technique can be tocompare the amount of iron which determined to be present from thespectral analysis to the amount of iron that is expected to be presentin undamaged casing based on the known casing thickness (generallyexpressed in terms of casing outer diameter and weight per unit length)and determining iron loss due to corrosion. The undamaged casingresponse may be calculated or may be measured using an actual welllogging instrument moved through a known undamaged segment of suchcasing (or liner).

B. Capture Iron Yields

A method similar to the decomposition of the inelastic spectrum can alsobe used for the capture gamma ray spectrum. Iron content determined fromthe capture gamma ray spectrum can also be used for determination of theamount of iron in the casing/liner in a wellbore.

C. Inelastic Count Rate or Count Rate Ratio (IRAT)

The count rate of the individual gamma ray detectors during the neutronburst is very sensitive to the conditions in the wellbore due to limiteddepth of investigation. Comparison of inelastic (also referred to asburst) count rates in the different gamma ray detectors (e.g., as shownin FIG. 4) may also be used to indicate the presence or absence ofcasing when the wellbore fluid and surrounding formation properties areknown and/or are constant. Comparison of the burst inelastic count ratesin two or more different detectors may be performed directly in across-plot or indirectly by taking a ratio of count rates. One maydefine IRAT in this example and a total gamma ray count rate during theneutron burst made by a farther spaced detector with respect to a nearerspaced detector. Other embodiments may use energy discrimination forpurposes of which gamma rays to detect. FIG. 4 shows a cross-sectionaldiagram of a wellbore having a casing 141 therein. The casing 141 hastwo perforated intervals, shown at 144 and 146. A packer 148 is affixedto the interior of the casing 141 and seals an annular space between thecasing 141 and a production tubing 150 (referred to in some cases as a“velocity string”). The right hand side of FIG. 4 shows graphs withrespect to depth of inelastic spectral iron yield 140 and inelasticgamma ray detection ratio between two detectors at 142. The graphs 140,142 indicate severe corrosion from 3100 feet to 3000 feet and from 2860feet to 2930 feet depth. The corrosion indication coincides with zoneswhere the well is perforated, suggesting that corrosive produced fluidmay have caused the corrosion. Above 2830 feet depth, the presence ofthe packer 148 and a tubing 150 can clearly be observed due to theincreased values of the iron spectral yield curve 140 and reduced IRATcurve 142.

D. Decay Time

The decay time for gamma ray or neutron counts may be used in a varietyof ways to qualitatively or quantitatively detect the presence orabsence of iron in a particular wellbore.

(i) Borehole capture cross section (using gamma ray or neutrondetectors): Pulsed neutron tools have been used to determine a boreholecapture cross section to correct the formation cross section. Theborehole capture cross section may also be used to determine an amountof iron that is present, due to the fact that iron is a good neutronabsorber. Corrections may have to be made for the presence of fluids(e.g., chlorine based brine) and other materials in the interior of thecasing.

(ii) Slowing down time (using gamma ray or epithermal neutrondetectors): The decay of a gamma ray count rate or an epithermal neutroncount rate within less than 10 microseconds after the end of the neutronburst is an indication of the decay of the epithermal neutron populationnear the well logging instrument. A measurement of this decay time isthus very shallow laterally and may be very sensitive to the presence ofstandoff or formation porosity. The shallowness and sensitivity of thismeasurement to standoff and porosity can be used to indicate andquantify corroded casing.

E. Tool Positioning While Running the Log

Depending on the casing diameter, many pulsed neutron tools take up onlya small part of the cross sectional area of the casing. Generally, thetools are run eccentered (by means of a bowspring, gravity or otherpositioning method) to make the measurements more sensitive to theformation. In order to increase the sensitivity of the tool to theborehole or in order to make comparisons of formation effects toborehole effects, the well logging instrument can be run centered, orboth centered and eccentered in subsequent runs.

FIG. 5 shows an example computing system 100 in accordance with someembodiments. The computing system 100 may be an individual computersystem 101A or an arrangement of distributed computer systems. Thecomputer system 101A may include one or more analysis modules 102 thatmay be configured to perform various tasks according to someembodiments, such as the tasks described above with reference to FIGS. 3and 4. To perform these various tasks, analysis module 102 may executeindependently, or in coordination with, one or more processors 104,which may be connected to one or more storage media 106. Theprocessor(s) 104 may also be connected to a network interface 108 toallow the computer system 101A to communicate over a data network 110with one or more additional computer systems and/or computing systems,such as 101B, 101C, and/or 101D (note that computer systems 101B, 101Cand/or 101D may or may not share the same architecture as computersystem 101A, and may be located in different physical locations, forexample, computer systems 101A and 101B may be at a well location, e.g.,in the surface recording unit 107 in FIG. 1, while in communication withone or more computer systems such as 101C and/or 101D that may belocated in one or more data centers on shore, aboard ships, and/orlocated in varying countries on different continents).

A processor can include a microprocessor, microcontroller, processormodule or subsystem, programmable integrated circuit, programmable gatearray, or another control or computing device.

The storage media 106 can be implemented as one or morecomputer-readable or machine-readable storage media. Note that while inthe example embodiment of FIG. 5 the storage media 106 are depicted aswithin computer system 101A, in some embodiments, the storage media 106may be distributed within and/or across multiple internal and/orexternal enclosures of computing system 101A and/or additional computingsystems. Storage media 106 may include one or more different forms ofmemory including semiconductor memory devices such as dynamic or staticrandom access memories (DRAMs or SRAMs), erasable and programmableread-only memories (EPROMs), electrically erasable and programmableread-only memories (EEPROMs) and flash memories; magnetic disks such asfixed, floppy and removable disks; other magnetic media including tape;optical media such as compact disks (CDs) or digital video disks (DVDs);or other types of storage devices. Note that the instructions discussedabove may be provided on one computer-readable or machine-readablestorage medium, or alternatively, can be provided on multiplecomputer-readable or machine-readable storage media distributed in alarge system having possibly plural nodes. Such computer-readable ormachine-readable storage medium or media may be considered to be part ofan article (or article of manufacture). An article or article ofmanufacture can refer to any manufactured single component or multiplecomponents. The storage medium or media can be located either in themachine running the machine-readable instructions, or located at aremote site from which machine-readable instructions can be downloadedover a network for execution.

It should be appreciated that computing system 100 is only one exampleof a computing system, and that computing system 100 may have more orfewer components than shown, may combine additional components notdepicted in the example embodiment of FIG. 5, and/or computing system100 may have a different configuration or arrangement of the componentsdepicted in FIG. 5. The various components shown in FIG. may beimplemented in hardware, software, or a combination of both hardware andsoftware, including one or more signal processing and/or applicationspecific integrated circuits.

Further, the steps in the processing methods described above may beimplemented by running one or more functional modules in informationprocessing apparatus such as general purpose processors or applicationspecific chips, such as ASICs, FPGAs, PLDs, or other appropriatedevices. These modules, combinations of these modules, and/or theircombination with general hardware are all included within the scope ofthe present disclosure.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

What is claimed is:
 1. A method for evaluating wellbore conduitcondition, comprising: accepting as input to a computer measurements ofat least one of (i) inelastic gamma rays made during emission a burst ofneutrons into the conduit from within the conduit at at least one spacedapart location from a position of the emission and (ii) epithermalneutrons or capture gamma rays therefrom detected at at least two spacedapart locations from the position of the emission within a selected timeafter the emission; in a computer, characterizing the at least one ofthe measurements of inelastic gamma rays and epithermal neutron orcapture gamma ray counts to estimate an amount of loss of iron in theconduit; and displaying a parameter related to the amount of iron loss.2. The method of claim 1 further comprising repeating the usingmeasurements made at different positions along an interior of theconduit.
 3. The method of claim 1 wherein the characterizing comprisescomparing characterized measurements made in a known undamaged sectionof conduit to the measurements made within the conduit.
 4. The method ofclaim 1 wherein the characterizing the measurements of inelastic gammarays comprises determining in the computer an iron yield from a spectralanalysis of the inelastic gamma rays.
 5. The method of claim 1 furthercomprising using measurements of inelastic gamma rays detected duringthe emission at at least a second location spaced apart from the atleast one location and in the computer determining a ratio of inelasticgamma rays detected at the at least one location and the at least oneadditional location and using the ratio to estimate a condition of theconduit.
 6. The method of claim 5 wherein the estimating the conditionfrom the ratio comprises measuring the ratio in a known undamagedsection of the conduit and comparing to the ratio determined in thewellbore conduit.
 7. The method of claim 6 further comprising using aratio determined from measurements of inelastic gamma rays madeproximate a wall of the conduit and a ratio determined from measurementsof inelastic gamma rays made proximate a center of the conduit, and inthe computer comparing the ratio from proximate the wall to the ratioproximate the center to identify portions of the conduit having ironloss.
 8. The method of claim 1 wherein the characterizing themeasurements of epithermal neutrons of capture gamma rays therefromcomprises in the computer estimating a neutron capture cross-section inthe conduit, and estimating an iron content of the conduit from theneutron capture cross-section.
 9. The method of claim 1 furthercomprising using measurements of inelastic gamma rays and epithermalneutron or capture gamma ray counts made proximate a wall of the conduitand made proximate a center of the conduit, and in the computercomparing the measurements made proximate the wall of the conduit to themeasurements made in the center of the conduit to identify areas of theconduit subject to iron loss.
 10. A method for evaluating wellboreconduit condition, comprising: (a) moving a pulsed neutron well logginginstrument along an interior of a wellbore having at conduit therein;(b) emitting at least one burst of neutrons into the conduit; (c)measuring at least one of (i) inelastic gamma rays made during the burstof neutrons into the conduit from within the conduit at at least onespaced apart location from a position of the emission and (ii)epithermal neutrons or capture gamma rays therefrom detected at at leasttwo spaced apart locations from the position of the emission within aselected time after the emission; (d) characterizing the at least one ofthe measurements of inelastic gamma rays and epithermal neutron orcapture gamma ray counts to estimate an amount of loss of iron in theconduit; and (e) displaying a parameter related to the amount of ironloss.
 11. The method of claim 10 further comprising repeating (b)through (e) using measurements made at different positions along aninterior of the conduit.
 12. The method of claim 10 wherein thecharacterizing comprises comparing characterized measurements made in aknown undamaged section of conduit to the measurements made within theconduit.
 13. The method of claim 10 wherein the characterizing themeasurements of inelastic gamma rays comprises determining an iron yieldfrom a spectral analysis of the inelastic gamma rays.
 14. The method ofclaim 10 further comprising using measurements of inelastic gamma raysdetected during the burst at at least a second location spaced apartfrom the at least one location and in the computer determining a ratioof inelastic gamma rays detected at the at least one location and the atleast one additional location and using the ratio to estimate acondition of the conduit.
 15. The method of claim 14 wherein theestimating the condition from the ratio comprises measuring the ratio ina known undamaged section of the conduit and comparing to the ratiodetermined in the wellbore conduit.
 16. The method of claim 15 furthercomprising using a ratio determined from measurements of inelastic gammarays made proximate a wall of the conduit and a ratio determined frommeasurements of inelastic gamma rays made proximate a center of theconduit, and in the computer comparing the ratio from proximate the wallto the ratio proximate the center to identify portions of the conduithaving iron loss.
 17. The method of claim 10 wherein the characterizingthe measurements of epithermal neutrons of capture gamma rays therefromcomprises estimating a neutron capture cross-section in the conduit, andestimating an iron content of the conduit from the neutron capturecross-section.
 18. The method of claim 10 further comprising usingmeasurements of inelastic gamma rays and epithermal neutron or capturegamma ray counts made proximate a wall of the conduit and made proximatea center of the conduit, and comparing the measurements made proximatethe wall of the conduit to the measurements made in the center of theconduit to identify areas of the conduit subject to iron loss.